Embodiments of the present invention generally relate to advanced metering infrastructure (AMI) used in electricity meters, gas meters, water meters and the like, and more particularly, the present invention relates to methods and systems related to an AMI command and control management application module and system.
Electricity generated at a power station may be produced using a plurality of energy sources, such as coal powered power stations, nuclear fission, hydroelectric stations, wind farms, solar photovoltaic cells, etc. This power generated at the power station is transmitted to users over a transmission grid. In recent years advancements have been made in transmission of power to an end user. One such advancement has been in the area of electrical power meters.
An electrical power meter may be implemented as an automatic meter reader (AMR) where the electricity usage is communicated one way to a meter reader. More recently, AMI has been developed. AMI differs from traditional AMR in that it enables two-way communications with the meter. AMI may receive data from the electric meter and communicate it over a network to a remote location. Also, AMI may send data to electric meters to perform various tasks.
Meter manufacturers sell meters to generate revenue. Some revenue is generated from metering system sales, but these systems are generally viewed as just another mechanism for selling additional meters. Meter manufacturers compete by providing better metering capabilities and functionality at a lower price.
Any given type of meter, whether it is water, electric, energy, or gas, measures a bounded set of quantities. These quantities represent the raw data collected by the device. Meter manufacturers were not able to use this raw metered data as a way to differentiate themselves from their competitors. Therefore, at the factory, meter manufactures conventionally loaded their meter's firmware with embedded capabilities, improved accuracy, or other applications (e.g., time of use (TOU), power quality (PQ) and/or alarm monitoring). These firmware applications use the meter's core set of data to compute the information that their meter data users (MDUs) need. Meter data users (such as utility distribution companies (UDC), energy service providers (ESP), or meter data management agencies (MDMA), etc.) used to purchase, at a low price, fully capable meters with all or some of their capabilities disabled (i.e., “turned off”). When additional functionality was needed, the MDU then purchased a license (or “key”) that gave it the ability to enable (“turn on”) the desired function in a meter. This method of selectively turning on meter functions allowed the meter manufacturer to create new license-based pricing models to make its product more cost competitive. Thus, in reality, the meter was still manufactured with all of the necessary hardware and applications in order to support the fullest possible range of functionality in an effort to more efficiently address possible future metering needs.
There are known drawbacks to that conventional metering approach, namely, increased functionality in the meter requires an increase in processing power and a commensurate increase in cost; the memory available “under the glass” in a meter is finite (i.e., in order to add an option one must remove another option or increase the memory); to upgrade or re-program a meter required a meter technician to drive to the meter location, physically remove the meter (or switch it out with a replacement meter) and then return it to the “meter shop” where the meter can be upgraded, and after the upgrade is complete, the meter was to be returned and re-installed; different meters require different interfaces and different communications protocols for retrieving data; increased application complexity in the firmware of the meter led to a higher probability of errors that may require upgrades; increased application functionality housed in the firmware of the meter typically requires complex configuration or programming of the end-device, which greatly increased the system management, coordination, and synchronization; and meter inventory must be increased in order to accommodate different configurations, functionalities, and versions of metering devices.
With the advent of improved communication technology, manufacturers are now able to add modem, network, and radio-frequency (RF) connectivity to their meters, thus permitting remote communications between meters and various meter data retrieval systems (e.g., automated meter reading (AMR) systems). However, there are limitations associated with these methods of remote communications: wireless communication with the meter is often limited to off peak hours determined by the various network providers; satellite-based communications are limited to line of sight communication between the meter and the satellite, thus limiting the times when the meter may be contacted; wireless and orbital satellite networks are costly, often billing per byte of data transmitted, thus limiting the amount of data which can effectively be transmitted.
Existing AMR/AMI systems are also limited in that they require several layers of applications and interfaces in order to communicate with connected meters. These layers implement the various communications protocols used by the numerous meter manufacturers and the various communications technologies that can be used to communicate with a meter (e.g., RF communication, satellite-based communication, etc.). As these meters are constantly revised, so are their communications protocols, requiring similar modifications to the AMR/AMI system. Industry standards intended to unify the communication and device protocols typically fall short by setting minimum requirements for compliance and/or providing manufacturer-specific mechanisms to allow variability and customizations. Therefore, AMR/AMI systems still often require meter-specific knowledge (e.g., communications and device protocols) to read the required data from meters offered by different manufacturers. Even with the current metering standards, the addition of a new or different meter would typically require additions and/or modifications to an AMR/AMI system. The increasing variety of meters presents an almost insurmountable challenge to the automated meter reading industry.
Deregulation of the electricity metering industry has created even more challenges. Prior to deregulation, a utility was responsible for generating, distributing, and transmitting electricity as well as purchasing, storing and installing metering devices, collecting metered data and processing customer billing. Now, with deregulation implemented throughout the United States, those duties and responsibilities that were the exclusive responsibility of the utility is now being divided among several service companies and providers who all need access to the meter and the meter data. All of these companies require access to either the data collected from the metering devices (e.g., power quality, outage, etc.) or to the calculated/processed data (e.g., quadrant data; validated, estimated, and edited (VEE) data, etc.) for their internal use (load management and monitoring, forecasting, etc.).
Today there are two prevailing AMR/AMI System business models: the exclusive ownership model (depicted in FIG. 1), and the service bureau model (depicted in FIG. 2). Certain AMR/AMI System deployments utilize a mixture of these two models in order to establish a workable business case. FIG. 1 depicts the exclusive ownership business model and shows two scenarios for AMR/AMI Systems that utilize public communication networks and private communication networks, or so-called fixed networks.
FIG. 2 depicts the service bureau business model and shows two scenarios for AMR/AMI Systems that utilize public communication networks and private communication networks.
A key difference between the public and private type communication networks is that the private network requires additional up-front cost to deploy the infrastructure of the fixed network to blanket one or more service areas. Although FIGS. 1 and 2 separate the public and private communications, AMR/AMI Systems exist that can utilize a combination or mix between public communication networks and private communication networks. In the exclusive owner business model (FIG. 1), the meter data users (MDUs) (i.e., ESPs, UDCs, MDMAs, etc.) purchase an AMR/AMI system with a significant up-front cost. In that business model, a particular MDU that is purchasing an AMR/AMI System is typically only interested in how the purchased AMR/AMI System will address its specific needs as identified in its business case. The MDU typically develops a business case that justifies the initial AMR System cost based on both measurable and non-measurable benefits. Some of the measurable benefits include: meter reading staff and infrastructure reductions, cost reductions for hard-to-access meter reading, connect/disconnect staff reductions, accurate and timely outage restoration, reduction in theft or tampering. Some of the non-measurable benefits include: faster and more frequent meter readings, thus yielding a higher level of customer service/retention, better positioned for competition in a deregulated energy market, ability to provide other types of services (i.e., new rates, flexible billing, etc.), other future uses for the metered information.
Taken alone, the measurable benefits listed above typically may not justify the expense incurred by purchasing an AMR/AMI system. Consequently, the number of large AMR System deployments has not reached expectations.
In the service bureau business model (FIG. 2), a service bureau (e.g., an MDMA, (hereinafter also referred to as a “vendor”) such as Silver Spring Networks) purchases an AMR/AMI system with a significant up-front cost, and then provides access to the collected meter data to subscriber MDUs, such as a utility company. This business case is built on the value of the metered information. It assumes the service bureau will recoup the cost of the AMR system by selling meter reads or metered information to multiple MDUs (ESPs, UDCs, etc.). From the perspective of the MDU, many of the quantifiable and non-quantifiable benefits discussed above can be met using this model, with timely access to the correct set of metered information. In this model, the MDUs do not own and operate the AMR System, which is the responsibility of the service bureau operator. In this model, the MDUs pay for the information they require. This reduces the up-front costs for the MDUs over purchasing their own AMR/AMI System and provides them with the option of a pay-per-use model. The service bureau model could create some conflicts, or perceived conflicts, when competing MDUs utilize the same service bureau for metered information. In the service bureau model, the MDUs need to be able to add value by developing or buying applications that allow them to differentiate themselves from their competitors.
After the second business model becomes operational, a utility may have an interest in implementing in-house system capabilities offered by the MDMA. A utility may develop an interest in internally running an AMI application currently maintained by an MDMA or vendor. The interest may stem from national security concerns, as the MDMA system may have the capability to disconnect meters or power to commercial or private utility customers. However, one problem of implementing such system in-house is that once the MDMA system has been implemented in a particular manner, applying a set of open standards or an MDMA-specific set of configurations, it may become cost-prohibitive to move such application to the utility. For example, it could take years to retrofit a system so that it can be made compatible with enterprise software that is run by the particular utility. The present invention solves those problems.